Wellbores are generally drilled using a drilling rig that supports and rotates a drill string having a drill bit at its lower end. Drilling rigs employ either a block and tackle or hydraulic means to raise and lower the drillstring, and may employ a rotary table or a top drive to rotate the drillstring. Fluid is circulated through the drillstring and bit to clean the bit and wellbore. A downhole motor or turbine is sometimes used near the bit to allow drilling to progress with or without rotation of the drillstring at the surface; for example, when directional drilling operations are conducted.
The drillstring initially hangs in tension with its weight supported by a hook on the travelling portion of the suspension system. The hook also supports the top drive or Kelly and swivel used to rotate and circulate through the drillstring. The total load carried by the hook is commonly referred to as hook load (HL), and is often reported in units of pounds force or Newtons.
The drilling sequence typically begins by increasing the pump strokes per minute (SPM) until a desired flow rate (Q) of drilling fluid, typically expressed in gallons per minute or liters per minute, is circulated through the drillstring and borehole. The pump pressure (Pp), typically expressed in pounds per square inch or bar, required to circulate at a given flow rate with the bit off bottom is herein referred to as the off-bottom pressure or pressure tare (PT). Bit rotation is then established by rotating the drillstring at the surface and/or by pumping through a downhole motor or turbine. Bit rotation speed ωb, typically expressed in revolutions per minute (RPM), is computed from the sum of surface rotation speed ωs and motor/turbine rotation speed ωm, where the latter is typically computed as the product of flow rate and a motor/turbine factor with units of rotations per unit volume of fluid circulation.
The drilling sequence continues by lowering the drillstring into the well via the suspension system. When the bit makes contact with the bottom of the hole, a portion of the weight of the drill string is consumed at the bit-formation interface as the bit penetrates the formation. This load is commonly referred to as the weight on bit (WOB), and is typically expressed in pounds force or Newtons. WOB is computed by subtracting the instantaneous hook load with the bit on bottom from the value recorded with the drillstring off bottom, herein referred to as the off-bottom hook load or hook load tare (HLT).
Torque, usually expressed in foot-pounds or Newton-meters, must be applied at the surface to rotate the drillstring and/or counteract the torque generated by the downhole motor as the bit drills ahead. The torque required to rotate the drillstring while the bit is off bottom is referred to herein as the off-bottom torque or torque tare (TT). The torque consumed by the bit as it drills ahead, herein referred to as the torque on bit (TOB) or differential torque, may be computed by subtracting the torque tare from the instantaneous torque measured with the bit on bottom. TOB is, in general, proportional to WOB.
The circulation pressure with the bit on bottom may be higher than that with the bit off bottom, especially when a downhole motor or turbine is used. The difference between the instantaneous pump pressure when the bit is on bottom and the pressure tare is referred to herein as the differential pressure (DP). When a downhole motor is used, DP is directly proportional to the output torque of the motor, which, for motors placed near the bit, is equivalent to TOB. Manufacturers of downhole motors often publish tables or charts showing the constant of proportionality between DP and motor output torque, often expressed in terms of foot-pounds per psi or Newton-meters per bar, for a given flow rate. These constants provide a secondary means for estimating TOB; that is, DP and flow rate are measured, the constant is obtained from the table, and the TOB estimate is computed.
The rate of penetration (ROP) of the bit into the formation, usually reported in units of feet per hour or meters per hour, depends on the magnitudes of the weight on bit, the bit rotation speed and the flow rate. The torque on bit is also dependent on these parameters.
If the rate at which the drill string is lowered at the surface exceeds the rate at which the bit can penetrate the formation at its instantaneous combination of WOB, ωb and Q, the WOB increases until a state of equilibrium is attained, at which point the bit ROP is identical to the drill string descent velocity at the surface, which is also known as block descent velocity (BDV), top drive descent velocity (TDV), or surface ROP (SROP). If, as drilling proceeds, a softer formation is encountered and BDV is less than the rate at which the bit can penetrate the formation at its instantaneous combination of WOB, ωb and Q, the load on the bit “drills off” as the drill string extends until the WOB and drill string descent rate are once again in equilibrium. The time required to reach equilibrium, alternately referred to herein as the time required to reach steady state, depends on a number of factors, including well depth, drill string composition and formation properties.
Drilling performance is often quantitatively assessed in terms of cost per foot drilled (CPF) or average ROP over a hole section or a bit run, and is affected by uncontrollable and controllable factors. The former include characteristics of the geological formation, the pore and fracture pressure gradients, subsurface temperature gradients and the vertical depth at which formations are encountered. The latter include factors specified prior to drilling, such as the type of drilling fluid used and the composition of the drillstring (including type of downhole motor used), and factors that can be manipulated while drilling proceeds, such as pump stroke rate (which, for a given pump configuration, governs flow rate of the drilling fluid into the wellbore), rotary speed of the drill string and BDV. These manipulated variables (MV), in turn, affect parameters that can be measured and controlled, herein referred to as control variables (CV), such as WOB, TOB, the total torque required at the surface to rotate the drillstring, circulating pressure measured at the surface, downhole motor differential pressure, et cetera.
The selected values, or magnitudes, of the manipulated and controlled drilling parameters highly influence the efficiency of the drilling process. For example, ROP generally increases substantially linearly with increased WOB, but there is a limit to this relationship, as the drilling process becomes inefficient at high values of WOB as a result of factors such as increased wear of the drill bit, bit balling, insufficient borehole cleaning, and drill string vibration. The latter can include axial vibration, lateral vibration or torsional vibration. Also, the drilling process may become inefficient at relatively low values of WOB, especially when drilling into hard geological formations. Moreover, the transient effects on WOB, TOB and ROP caused by variations in formation characteristics and downhole conditions further complicate identification and maintenance of parameters that optimize the drilling performance of the drilling assembly.
Historically, manipulation of BDV to maintain a desired value of WOB or some other control variable has been done manually by the driller. More recently, control systems on drilling rigs have been augmented to include “automatic drillers” (auto-drillers) that use computer logic to manipulate BDV such that target values (also known as setpoints) for certain control variables are maintained. Proportional-integral-derivative (PID) or Heuristic controllers are often employed for this purpose. Some auto-drillers allow multiple control variables to be considered simultaneously, for example surface ROP, WOB and motor differential pressure. In this case, the controller adjusts the BDV until the lowest value that causes a setpoint to be reached is found. The process is known as a “low select.” The ability of the controller to hold the desired setpoints depends on its structure and tuning. Proper tuning requires quantification of the dynamic response of the system, which changes as drilling conditions change. Procedures for quantification of system response, such as step tests, are well known in the controls industry, but these can be time consuming and are not commonly applied as drilling progresses. As a result, the ability of auto-drillers to hold setpoints is suboptimal, and “overshoot” of control variables can cause machine protection limits to be reached. This interrupts the drilling process and forces the driller to intervene to correct the situation. The lost time contributes to increased cost per foot and decreased average ROP.
The setpoints themselves are selected by the driller based on experience, theory, or analysis of drilling data from other wells that have been drilled in the vicinity. Methods for identifying combinations of drilling parameters that, if used, will minimize a given objective function (e.g. cost per foot) have been described in the literature, but these require analysis of historical data in an area, constructing empirical models that provide a “best fit” of the data, and using them to find preferred parameter combinations. These approaches are limited in that they (1) are time consuming, (2) require availability of offset data to calibrate models, (3) are only applicable over ranges of drilling parameters used in offset wells, (4) are heavily dependent on bit attributes that are difficult to ascertain and can vary widely from one design to another, and (5) are only marginally applicable to wells where different formations and/or different well trajectories are used. In view thereof, drilling operations typically do not operate at optimum conditions but rather at constant values of weight on bit, rotary speed, and flow rate of drilling fluid, which values are expected to work well.
More recently, routines for closed loop control have been described, including the use of either minimum mechanical specific energy (MSE) or maximum ROP as the objective and manipulation of drilling parameters to construct response surfaces for ROP vs. WOB and rotation speed (RPM) so as to identify local maxima. These approaches are limited in usefulness because they are either (1) highly sensitive to noise in drilling data, and thus require considerable computational overhead; (2) ineffective because they require excessive time to implement, during which drilling is conducted using sub-optimal combinations of parameters; (3) incomplete because they do not effectively address constraints that should limit parameter selection, e.g. indications of dynamic dysfunction.
Hence, there is a need for a system and method for control and optimization of drilling parameters that avoids the shortcomings of existing systems.